Monday, July 15, 2019

Permanent Monitoring- Looking at Lifetime Reservoir Dynamics

Permanent monitoring systems measure and record well performance and reservoir behavior from sensors placed downhole during completion. These measurements give engineers information essential to dynamically manage hydrocarbon assets, allowing them to optimize production techniques, diagnose problems, refine field development and adjust reservoir models. 

Reservoir development and management traditionally rely on early data gathered during short periods of logging and testing before wells are placed on production. Additional data may be acquired several months later, either as a planned exercise or when unforeseen problems arise. Such data acquisition requires well intervention and nearly always means loss of production, increased risk, inconvenience and logistical problems, and may also involve the additional expense and time of bringing a rig onto location. 

Permanent monitoring systems allow a different approach. Sensors are placed downhole with the completion string close to the heart of the reservoir. Modern communications provide direct access to sensor measurements from anywhere in the world. Reservoir and well behavior may now be monitored easily in real time, 24 hours a day, day after day, throughout the lifetime of the reservoir. Engineers can watch performance daily, examine responses to changes in production or secondary recovery processes and also have a record of events to help diagnose problems and monitor remedial actions, rather like monitors in a power plant's control room.

Most systems in operation record bottom hole pressure and temperature, but other measurements, such as downhole flow rate, are being introduced and may become common in the future. However, pressure and temperature provide dozens of beneficial applications. This article reviews the development of permanent monitoring, looks at applications with several examples and describes the hardware.

 Early Days

Permanent monitoring has its roots in the early 1960s on land wells in the USA. Pressure gauges were needed to monitor the performance of secondary recovery projects, such as waterfloods or artificial lift schmes, where they were required downhole for several weeks. In many cases, the only option available was to run a standard pressure gauge on the end of the completion string. The cable for power and data transmission was passed through an insulated connector in the Christmas tree, strapped to the outside of the tubing and then ported back inside the tubing just above the gauge leaving the bore free of any obstructions. Even though the hardware was simple by today's standards, these early examples proved invaluable to oil companies and showed the diverse use of and benefits from the pressure data gathered. 




 One example from 1962 is typical of the period. Henderson 6 was the second well completed by the Coronado Company in the Bell Sand of the Old Woman Anticline, Wyoming, USA. A permanent pressure gauge was placed below a conventional pump in a 2400-ft well for interference testing and to determine the productivity index. Initial bottomhole pressure (BHP) was 680 psi. 

The well produced 340 barrels of oil per day (BOPD) with a 60-psi drawdown, but quickly suffered from increasing water cut. Bottomhole pressure returned to 680 psi indicating complete water breakthrough - possibly by water coning. By modifying production and monitoring downhole pressure changes it quickly became apparent that the coning problem would not repair itself and that the well would have to undergo workover.







Tuesday, May 28, 2019

Modeling Logs for Horizontal Well Planning and Evaluation

Horizontal wells can increase production rates and ultimate recovery, and can reduce the number of platforms or wells required to develop a reservoir. They can also help avoid water or gas breakthrough, bypass environmentally sensitive areas and reduce stimulation costs.

As exploration and development budgets tighten, companies are becoming more efficient by drilling fewer, well-placed holes. Reentry and multilateral wells are growing in number, along with short-radius wells. There are greater expectations and smaller margins for error in driling today's horizontal wells. 

Drilling horizontal wells presents formidable challenges. Planning trajectories, choosing fluids, steering, formation evaluation and completion- each stage is a huge task. Several stages-planning,steering and formation evaluation- benefit from combining the efforts of geologist, log analyst and directional drillers. 

A powerful partner in all these stages is forward modeling, or log simulation. Other industries are using simulation to help train pilots , model aircraft and automobile reliability and response, design buildings, test weapons, record music, predict weather- the list is endless. In the oil field, modeling helps make efficient use of logs in horizontal wells in two ways- first by predicting logging-while-drilling (LWD) tool response to guide directional drilling, and second by constraining formation evaluation when the conventional assumptions of a vertical well no longer hold. 

Directional drilling practice and technology have evolved to the point where , given a good plan, the target can be hit with high accuracy. The drill bit can be placed within a target the volume of an engineer's office at a depth and lateral offset of a few miles. Trajectories are becoming more complex as directional drillers push the technology to its limits in "designer" wells. To improve the odds of these wells hitting the target, they are carefully planned in two steps: definition of the target from maps and logs, then design of a wellbore trajectory to hit it. 

No plan, unfortunately, is foolproof. Uncertainties in the position of the target , combined with unpreditictability of structural and stratigraphic variations, even in developed fields, can cause directional drillers to lose their way. The chance of going astray declines significantly, however, with the use of real-time formation evaluation logs and comparison of the logs with modeled cases to gauge the position of the tool within the sequence of beds. The INFORM Integrated Forward Modeling program provides an interface for building a formation model and simulating log response, allowing drillers to anticipate what's ahead. We look first at modeling for horizontal well planning, then explore how the INFORM system facilitates postdrilling visualization of LWD and wireline logs in horizontal wells.  


Model First, Then Drill

Often the objective of drilling a horizontal well is to penetrate the reservoir but stay close to a caprock shale or gas-oil contact- to drill parallel to a boundary or a contrast in material properties- for thousands of feet. Such a viewing angle is unusal for electromagnetic tools, the tools most commonly used for steering. Other measurements, such as gamma ray and density, are also affected by the horizontal geometry, giving an asymmetric response as they lie against the floor of the borehole. 

Because most resistivity tools probe several feet into the formation, they are affected by resistivity inhomogeneities in the vicinity of the well and even ahead of the drill bit. This early warning feature is beneficial to directional drillers, who harness it to steer wells into target layers or away from problem zones before they are encountered by the bit. This "proximity effect" can be accurately modeled during predrilling planning to provide a road map for drilling.

In a planning example from the North Sea, Jim White of Schlumberger Wireline & Testing in Aberdeen, Scotland, used log modeling to demonstrate the feasibility of landing the well in a thin sand and avoiding high-resistivity , calcite-cemented , tight streaks. Forward modeling computed the response of the CDR Compensated Dual Resistivity tool with its two depths of investigation- shallow from the phase shift measurement and deep from the attenuation log. When the wellbore came to within 3 ft of the calcite zone, the modeled attenuation and phase shift curves crossed, because the deeper-reading attenuation measurement senses the high-resistivity calcite. 

The CDR logs acquired when the well was drilled corroborated the modeled predictions. Based on the simulations, the signature of the lower boundary- the deep reading crossing over the shallow was recognized while drilling, and the well was steered away. Had the well entered the cemented zone, drillers estimated they would have spent several days trying to get back on target. 

Geologist from Chevron Niugini are using INFORM forward modeling to plan and geosteer horizontal wells in the Iagifu Hedinia field, within the Southern Highlands Province of Papua New Guinea. Located in Papuan Fold and Thrust belt, this field is part of a double anticline complex in the Hedinia thrust sheet. The major oil reservoir is the Lower Cretaceous Toro sandstone. Within the Toro, the hydrocarbon accumulation consists of an oil band up to 218 meters [ 715 ft] thick overlain by a gas cap. Gas cap expansion and gravity drainage are the major drive mechanisms for the field, with support from the Toro aquifer making a minor contribution.

Development well planning and drilling are complicated by the complex fold geometry. Unfortunately, the rugged karst topography created in the Darai Limestone at surface prohibits the acquisition of usable seismic data. For predicting the subsurface reservoir geometry, geologist rely on surface geological mapping, side-scan radar imagery, dipmeter data and correlation logs from adjacent wells.

In order to maximize productivity and ultimate recovery from the horizontal wells, wells are programmed to be horizontal in the Toro oil reservoir at a level of 15 m [50 ft] above the oil-water-contact. This enables the wells to produce oil at lower solution gas/oil ratios (GOR) and should delay breakthrough from the advancing gas front. 

During drilling to the Toro objective, the landing phase is critical to the success of the horizontal well program. With an unstable Alene shale section overlying the Toro, it is important to minimize the amount of horizontal section drilled before encountering the top Toro. Conversely, encountering the Toro during the build section of the well course, before reaching horizontal, can result in loss of productive interval since this hole section may be too close to the current gas-oil contact and would not be perforated. The Alene is drilled with mud weights in the range of 12 to 14 ppg, while the current reservoir pressure in the Toro are in the 4.5 to 5.5 ppg equivalent range. To prevent loss circulation problems and possible loss of the hole, it is necessary to identifiy the top of the Toro casing point before penetrating more than 1.5 to 3 m [ 5 to 10 ft] of the sandstone. 













An accurate predictive model of the Toro anticlinal geometry resulting from recognition of overlying stratigraphic markers while drilling -as well as the ability to determine the structural attitude of these layers - increases the probability for a successful landing phase. With INFORM processing, a model of stratigraphic interval above the target can be built using well logs and dipmeter data from nearby wells along with geological structure models developed for the planned horizontal well. LWD responses for the potential range of structural dips within a particular area of the anticlinal fold can be simulated. 

As the well course builds to horizontal, the geosteering specialist and geologist correlate major stratigraphic LWD markers and estimate the structural dip of a stratigraphic unit in the plane of the well course by optimizing the match between the LWD curves and the model log curves. The calculated structural dip estimates are compared to those in the geologist's predicted fold geometry cross-sectional model. The new dips are then used to correct the subsurface structure model and revise the top target coordinates.

During the planning for the first well, IHT-1, gamma ray and resistivity logs from three nearby wells were used to create a model for computing CDR responses for the full range of possible structural dip magnitudes along potential well trajectories. The responses were stored in a relative angle data base. The programmed well course was oblique to the strike of the Toro in this area of the Iagifu anticline, and was designed to be horizontal 15 m above the oil-water contact. This entry point is depth-constrained by the predicted oil-water contact level, and laterally constrained by the projected position of the Toro entry point, determined by projecting the Toro structural dip away from well control points higher on the anticlinal flank. The kick-off depth and deviation angle build rate depend on knowing this entry position. (picture)











During the drilling of well IHT-1, a computer structure model with sections of 6 degree and 8 degree apparent dip was constructed with the INFORM system, using data transmitted via satellite link. The stratigraphic horizon boundaries, dip magnitude and true vertical depth of each section was determined from the match between the measured CDR logs and the modeled logs. This match is consistent down to the Toro, indicating the structural dip model is a good representation of the actual Toro subsurface structure. 


Typically the CDR tool, producing characteristic horns at high-angle bed boundaries, is run to land wells. FOr the IHT-1 well bottomhole assembly configurations, however, this tool is located 18 m [60 ft] behind the bit. To precisely locate the 9 5/8 -inch casing setting depth at the top Toro, the last bit trip is run with the Geosteering tool, an instrumented steerable downhole motor with two resistivity sensors.

 The primary purpose of the Geosteering tool is to drill the horizontal drainhole and confirm that the well is above the oil-water contact in each sand. Normally Geosteering tool data are not acquired in the upper 6 to 9 m [20 to 30 ft] of the Toro, until the tool signal receiver clears casing. Because of mechanical problems, the 9 5/8 in. casing in IHT-1 ended 27 m [90 ft] above the Toro. This allowed the Geosteering tool to acquire data across the shale-sandstone resitivity contrast at the top of the Toro.

Unexpectedly, IHT-1 entered the dipping Toro reservoir beneath a present-day oil-water contact at 8741 ft true vertical depth (TVD). The contact was apparently 15 to 18 m [50 to 60 ft] shallower than predicted, probably due to pressure depletion of the upper Toro reservoir in this area of the field. The bit resistivity gave an immediate indication of water-saturated Toro. The planned trajectory was modified to build angle to greater than 90 degrees in an upward trajectory, crossing the oil-water contact from underneath. During drilling in the mid-Toro, the well encountered lost fluid circulation problems, possibly at a fault or fracture zone. With sudden unloading of the borehole, collapse occured in the unstable shale openhole section above the Toro, and the hole was lost.

IHT-1A, a sidetrack designed to take a parallel well path, was planned using the structural attiiude data and oil-water contact information from IHT-1. A short 30.5 -m [100 ft] , 8 1/2 inch pilot hole was drilled at the end of the buildup section with the Geosteering tool to "geostop" exactly on the shale-sandstone reservoir boundary. This hole was enlarged, and the 9 5/8 inch casing set just on the reservoir top. As expected, dips were close to those in IHT-1, and the well was landed within the Toro oil leg as planned, 15 m above the present day oil-water contact. It continued for 427 m [1400 ft] across the three main Toro reservoir sandstone members. The well was completed as an oil well, producing more than 10,000 stock tank barrels of oil per day, at solution GOR. 

Another well, IHT-2, on the same structure, encountered 55 degree dips, much steeper than the 22 degree anticipated. These were successfully modeled and the well path modified to hit the target.

After drilling, Model Again

Once drilled and logged, horizontal wells continue to pose challenges in visualization and formation evaluation. Log simulation can help verify a formation model or the location of  a well in space, to use for future development planning and quality control. More importantly, modeling helps untagle true formation properties such as formation fluid resistivity, Rt , and water saturation, Sw from the melange of shallow and deep responses of while-drilling and wireline tools.




In the Gulf of  Mexico, Lee Lehtonen at Mobil Exploration and Producing in New Orleans Lousiana, USA tested simulation to validate the model of a horizontal well designed to tap multiple compartments in a faulted reservoir. The horizontal well was to traverse four fault blocks.












Pay in the first and fourth blocks would be isolated by enough shale to allow setting external packers. In this case, INFORM modeling showed how LDW porosity logs could be used to distinguish a change in formation properties associated with faulting from changes encountered in a new stratigraphic layer. 

The ADN Azimuthal Density Neutron tool measures-while drilling- bulk density, ultrasonic standoff, photoelectric factor and neutron porosity. Magnetometers continously measure tool orientation , and results are distributed into readings above, below and to each side of the borehole. This allows discrimination of the orientation of planes of porosity and density discontinuity in the formation. 

In the Mobil well, CDR and ADN data were recorded into memory while drilling, and data were brought uphole with each bit change. These logs were compared with logs simulated using a formation model built from the known structure and pilot well logs. During the fifth bit run, the density tool encountered a shale-sand contact. Examination of the density porosity logs shows that the average and bottom quadrant curves both detect the interface at the same measured depth, XX340 ft. Comparing the acquired and simulated logs shows the contact can be modeled as a fault separating shale from sand. 

















Sunday, May 12, 2019

AVO in VSPs

When a wavefront hits a boundary at vertical incidence, the amount of compressional energy reflected and transmitted is dependent only on the contrast of acoustic impedance- density times compressional velocity- of the rocks at that boundary. But when the incident angle is not 0 degree, the amount of compressional energy reflected of tranmitted depends on the angle of incidence, or source offset, and contrast in densities and shear and compressional velocities. In such cases, the reflection AVo can be measured and analyzed to yield information about lithology and pore fluid through their effects on density and compressional and shear velocities. 

Carrying out a walkaway VSP with the receivers straddling such a boundary allows direct measurement of the variation in amplitude with offset that arises from lithology and fluid properties above and below the reflector. The results can be analyzed for fluid and lithology identification in a wide zone around the well. Formation properties inferred from VSPs can be integrated with those interpreted from well logs and measured directly from cores. In this way the VSP can also provide independent calibration of the same amplitude variation seen across a surface seismic reflection point gather- a gather is thee collection of traces that reflect at the same point, but at different angles, or offsets.

Calibrating the surface seismic AVO data with the VSP AVO response brings added value by:


  • establishing viability of using AVO to map a reservoir.
  • reducing the risk involved with the added cost of AVO studies
  • improving the reliability of AVO interpretations
  • quantitatively assessing the effects of processing on the AVO response.


To establish whether AVO is applicable as an interpretation tool for a particular reservoir, the expected AVO response is usually modeled. This requires knowledge of the model parameters, including shear velocity. Dipole shear sonic logging tools are used to measure shear velocities even where this velocity is slower than the borehole fluid velocity.









However, use of density and velocity log data to model anticipated AVO anomalies has not always succeeded in fully explaining the AVO response observed on surface seismic gathers. The reasons for this are many and include reflectivity mismatches between surface seismic and log data, wave propagation effects through fine layers, tuning effects (constructive and destructive interference at seismic wavelengths), geometric effects, processing-related issues and intrinsic anisotropy.

Borehole seismic data can quantify these effects. VSPs provide an independent measure of the seismic AVO response and the ability to include necessary effects in the forward modeling to satifactorily explain the origins of the surface seismic AVO response. Anisotropy is one such effect - one that can both mimic and mask AVO responses, giving false hope for or concealing the presence of hydrocarbons. 

Informaiton about anisotropic velocities for forward modeling often comes from measurements made on cores. But being scale-dependent, anisotropy may be different at the seismic wavelength scale. Therefore, it is better to measure  the elastic anisotropy at the seismic scale. 

In 1994, at Schlumberger Cambridge Research in Cambridge, England, Doug Miller proposed a method to do this using the arrival times from a walkaway survey to provide a measure of compressional velocity anisotropy in a shale, and from this to characterize the elastic properties of that shale, governing compressional and vertically polarized shear waves.

Shale consists of finely- layered clay platelets and exhibits an anisotropy called transverse isotropy (TI). The acoustic properties vary depending on whether waves propagate with particle motions parallel or perpendicular to the platelet layers- often thought of as horizontally or vertically because the clays usually lie flat.

Miller proposed that the vertical slowness - the inverse of velocity - of a shale may be measured across an array of geophones for each shot point offset along a walkaway profile. And the horizontal slowness can be measured at a single receiver location for adjacent shots in the same profile, providing the subsurface layers are essentially flat. A crossplot of these measurements for each shot position defines the compressional anisotropic response of the shale. A curve fitted to these data points provides a solution to the equations that deliver shear anisotropy through a complete description of the elastic properties of the shale.

These research efforts have been put to practical use in the BP-operated Forties field in the UK sector of the North Sea. The ultimate aim is to enable AVO attributes to be mapped with confidence from 3D surface seismic data. To achieve this,  a detailed evaluation of shear velocity anisotropy in the formations overlying the Forties sand has been undertaken to build a velocity model. The data used included acoustic measurements from preserved shale and sand cores, a full suite of logs- including standard density and DSI Dipole Shear Sonic Imager Logs- in addition to walkaway, rig source and vertical-incidence VSP data.

Initially, two models were generated, one assuming the shale overlying the reservoir sand was isotropic and another in which TI anisotropy was introduced. Differences in amplitude response between the two models were immediately observed, particulary at far offsets for the interface between the shale and the reservoir sand at 1.07 normal incidence time. 

The predicted response assuming an anisotropic shale was validated by the amplitude measured in the calibration walkaway. This implies that the effect of the anisotropic velocity in the shale must be taken into account before attributing the AVO response in the surface seismic data to effects of fluid in the reservoir. 

It is clear from this study that the combination of AVO measurement from VSP and log-based, anisotropic forward modeling provides a powerful methodology for calibrating AVO responses observed on surface seismic data near wells in low dip structures. Where AVO analysis is used as the basis for hydrocarbon indication in fields with existing wells, the method helps identify the origin of observed AVO effects, determining whether large-scale AVO analysis and reprocessing effort are worthwhile in terms of achieving the desired objectives. 

The greater understanding of observed AVO effects should minimize the risk of missing genuine hydrocarbon-related AVO anomalies or of misinterpreting anomalies caused by other factors, such as anisotropy.

 
 






Tuesday, April 9, 2019

Borehole Seismic Data

Seismic surveys in the borehole deliver a high-resolution quantitative measure of the seismic response of the surrounding reservoir. Although these measurements may be used alone to image local features, they may also be tied with well data-logs and cores- and then related to more extensive surface seismic data. Advances in borehole geophysics are helping realize the full potential of existing data to create a sharper image of the reservoir. 


It's a matter of resolution. Surface seismic surveys deliver  one of the few quantitative measurements of reservoir properties away from wells, making the technique central to structural mapping of the entire reservoir volume. However, surface seismic waves cannot resolve features smaller than 30 to 40 ft [9 to 12 m] . On the other hand, logs and cores resolve features on the scale of a few feet down to about 6 inches [15 cm]. Reconciling these two measurement scales to get the optimal picture of the reservoir volume is a problem that has long challenged the industry.

Borehole geophysics has a foot in both the logging and surface camps. From the vantage of the wellbore, seismic data often have higher resolution than their surface seismic counterparts. Depths of each borehole receiver are also known, providing a better tie to the formation properties provided by petrophysical, core and other in-situ measurements and relating them to the 3D seismic volume. 

The idea of locating a receiver downhole and a seismic source at surface is not new. For more than half a century, the check shot has helped to correlate time-based surface seismic surveys with depth-based logs. Check shots check the seismic travel time from a surface shot to receivers at selected depth intervals. Subtraction of times, combined with the depth differences, yields vertical interval velocities and thus relates well depths to surface seismic times. 

In vertical seismic profiles (VSPs), the spacing between downhole geophone levels is considerably closer than for check-shot surveys. VSPs use high-quality full waveforms that include reflection information rather than just the time of first arrivals - or first breaks- to create an image of reflections near the wellbore. Building on this technique, 2D reflection images have been obtained by offset and walkaway surveys with sources and receivers in a variety of configurations that address most reservoir problems.

Yet, despite these and other developments, borehole geophysics has for many years failed to gain the status in reservoir characterization that some industry specialists think it deserves. Now, thanks to improved quality and increased confidence in the match between borehole and surface seismic data, borehole geophysics seems to be moving into an increasingly valued position.

Before examining how borehole seismic data are being used to successfully integrate other data, this article will illustrate how the scope of VSP is broadening through the development of horizontal, 3D and through-tubing techniques.

Broadening the Scope of VSP Applications

In the deviated and horizontal wells of the North Sea,the most common type of borehole seismic survey is the vertical-incidence VSP. These are often called walk-above surveys because, as the geophone is moved along the deviated section of borehole, the source is kept vertically above it, "walking above" the well.  In VSP terms, a horizontal well is an extreme version of a deviated well. Like other VSPs, deviated well surveys may be used for locating the well in the 3D surface seismic volume and assessing the quality of surface seismic surveys. Also, the technique may be employed for measuring lateral velocity variations and for imaging faults and structures below the wellbore. 

The following example of a walk-above VSP was carried out in late 1994, in a North Sea well with a 1.2 kilometer horizontal section. There were two main objectives. The first was to measure a suspected lateral velocity anomaly that may have been creating artifacts in the surface seismic data. The second was to obtain a high-resolution seismic image below the deviated portion of the well. An additional objective was to obtain seismic image in the horizontal part of the well.




Data were collected in ther vertical and deviated portions of the cased well using the conventional wireline-conveyed ASI Array Seismic Imager tool. In the horizontal section, a two-element CSI Combinable Seismic Imager geophone array was run on drillpipe in combination with a cement bond log. By decoupling the sensor module from the body of the CSI tool, the geophones are isolated from noise and distortions created by the drillpipe. 

As with any survey, the desired seismic image is produced using the reflected, or upgoing, wavefield. So the first processing task was to separate downgoing waveforms from upgoing. For walk-above surveys in horizontal wells, this is far from straightforward, since unlike vertical and deviated wells, there is no apparent time difference across the array between the downgoing and the reflected upgoing waves. It is therefore impossible to use conventional techniques to distinguish between reflections and downgoing waves. To improve the image a number of special techniques were used, including:
  • multichannel filtering to attenuate noise and sharpen the desired signal
  • downgoing wavefield subtraction using a long filter length to estimate the downgoing wavefield
  • median filtering techniques to estimate and subtract the energy scattered by faults
  • enhancement of the desired upgoing signal
  • equalization of the reflected wavefield amplitudes from the horizontal and the build up sections.

The final image showed three important features: the two faults marked A and B, which appear where suspected in the reflected image, and the dip of the strata below the well. Formation MicroScanner data acquired during openhole logging were compared with the VSP, confirming the fault locations-seen as chevrons in the VSP - and the apparent dips.


In this case study, VSP processing was performed before Formation MicroScanner data were ready to interpret, and the VSP helped the interpretation by outlining the major features. The two data sets were then interpreted and refined together, providing a more complete description of near-well geology than was otherwise available. The results met the main objectives of the survey and delivered an image below the horizontal section. 











An alternative strategy for acquiring and processing horizontal VSP data exploits the different responses of geophones and hydrophones to differentiate downgoing energy from upgoing energy in horizontal wells. Geophones are clamped to the formation, and sense its motion. In contrast, hydrophones are suspended in the borehole fluid and are sensitive to fluid pressure changes as seismic wave passes in any direction. When the two sensor types show the same signal polarity for a downgoing wave, they show different polarities for the upgoing wave.  By taking the difference between signals received at the two types of sensors - for a signal consisting of a direct pulse followed by a reflected pulse- the direct wave is canceled and the reflection enhanced.

Complications arise from differences in the coupling and impulse responses between geophones and hydrophones. However, this approach has recently been applied in the field, enabling the extraction of related wavefields in a horizontal well and the imaging of reflectors below the receivers.

 3D VSPs

VSP imaging surveys, such as walkaways, have been used for a number of years to image structural complexity away from the borehole. These walkaway profiles are essentially two-dimensional, confined to the vertical plane containing the surface source and the borehole. 

Because of the proximity of the receivers to the target, like all VPSs, these 2D images usually have the advantage of being of higher resolution than their surface seismic counterparts. But, by definition, 2D walkaways don't describe the full volume of the reservoir. Fortunately, the acquisition principle may be extended to cover three dimensions by repeated profiling in parallel lines - in effect, by collecting a series of 2D walkaway surveys similar to marine 3D seismic data acquisition. 

The progression from 2D to 3D in VSP surveys is similar to the progression in the surface seismic technique , and offers equivalent benefits. Thus, 3D VSPs allow high resolution imaging to augment surface 3D surveys and make it possible to obtain  images beneath surface obstacles, such as platforms, and near-surface obstructions, such as shallow gas zones. In addition, because the acquisition conditions and processing steps of VSP surveys are accurately reproducible, 3D VSP opens up the possibility of time-lapse, or 4D, seismic surveying. 

However, progressing from 2D to 3D substantially increases the need for planning and logistics control. Similarly, the processing requirements are almost an order of magnitude greater. 

The first 3D VSP survey was run in 1987 in the Adriatic Sea Brenda field, operated by AGIP. Since then, there have been two 3D VSP surveys in the Norwegian Ekofisk field for Phillips Norway- where a large gas plume over the center of the structure prevents imaging using conventional 3D surface seismic techniques. Other Norwegian surveys probe the Eldfisk and Oseberg fields. 

In the UK North Sea, a 41-line, 3D walkaway VSP survey has been carried out in Shell Expro's Brent field. In this case, the aim was to acquire a survey with improved resolution compared with the 3D surface seismic survey. The image was then be used to produce an accurate structural map to aid the planning of horizontal development wells in the Brent slump- a crestal zone of complex faulting and collapse which contains a significant portion of the field's remaining oil reserves. 

The survey was executed from a well with a trajectory that allowed positioning the geophones to give three-dimensional illumination of the slump zone. The receivers consisted of five shuttles with fixed triaxial sensors, clamped 2000 ft [606 m] above the target during the entire survey. Once in the well but prior to shooting, the coupling between each of the shuttles and the formation was evaluated using internal shakers to ensure distortion-free data.

The seismic source consisted of a cluster of three 150 in 3 sleeve guns. To supply sufficient gas for 41 lines of 200 shots per line, four 5100 cubic meter nitrogen-filled tube skids were used. Simultaneously with the downhole data acquisition, each shot location on the surface was recorded using two differential GPS navigation system. 

To make the survey cost-effective, it was vital to minimize time spent acquiring data -every extra minute per sail line meant an additional 41 minutes of rig time. For example, to reduce the time the vessel took to maneuver between lines, a strategy was devised to wrap each line efficiently into the next. In the end, the data were acquired within the planned survey time of two and a half days, including a conventional VSP.

The 3D processing involves an extension of methods already developed for 2D walkaways-data preparation and navigation check, triaxial projection, wavefield separation, deconvolution and migration. 


In this case, the processing consisted of separate preparation and processing of all 41 lines up to the deconvolution stage. Then all 41 reflected energy profiles were accessed by the 3D VSP migration algorithms to place the reflections correctly in space.

The successful processing of these surveys required an experienced geophysicist with strong interpretative skills to make the correct decisions at each stage of the processing -for example, to ensure that all possible questions related to the influence of data quality had been resolved. These skills ensured that the image was interpreted in terms of reservoir structure without processing artifacts.

The migration process requires the computation of raypaths from each source and every receiver to every reflection point in the subsurface. The rays are traced through a velocity model of the subsurface that can vary in complexity between flat layers ( a 1D layercake) to complex structures in 2D or 3D.

For simple structures , a layercake velocity model, which reduces computation time, is sufficient.  However, using this model in more complex subsurface may lead to erroneous positioning of reflections and the incorrect focusing of real events. More complex velocity model increase the number of ray-trace computations required, but are better able to position reflected events and focus the wave energy.



The Brent structure varies in the dip direction but changes very little along strike. Consequently, the velocity model is more complex than a plain 2D model but not as complex as a full 3D model; the structure varies in one horizontal direction and is extruded into the other horizontal dimension to form a so-called "2.5D" model. In this, the volume may be thought of as filled with an infinite number of 2D sections. This allowed computational efficiency due to symmetry and ensured a close match with the actual Brent structure.

Shell concluded that the Brent 3D VSP improved vertical resolution and significantly improved horizontal resolution- resolving features on the order of 100 to 150 ft [ 30 to 45 m] as opposed to the original 3D surface seismic resolution of 200 to 300 ft [60 to 90 m] . The interpretation of the slump features has confirmed conclusions reached independently , demonstrating the technique's potential and reducing the risk of a proposed new 3D surface survey.

 Through-Tubing VSPs

The third application broadening the scope of borehole geophysics is the VSP through tubing. Thanks to hardware developments, cost-effective VSPs can be run in mature fields that promise significant economic benefits

Traditionally, borehole seismic surveys are acquired in exploration wells when they are drilled. However, in older fields, borehole seismic information is often needed to aid the reservoir engineer in areas where no new wells are planned, or to plan a new well. Now a slim seismic receiver may be deployed by a simple masted logging truck to acquire borehole seismic data through production tubing and inside casing during workover or while the well is still on production. This reduces acquisition costs and makes surveys in multiple wells possible during the same mobilization. 




In this way, a full range of borehole surveys may be carried out and the data may be used to tie log and production information to new 3D surface seismic surveys being run in older producing fields.

The slim seismic tool has a 1 11/16- inch outside diameter and may carry one single-axis geophone group or three orthogonally mounted accelerometers.The mechanicallytt actuated anchor has a maximum opening of 7 in. [17 cm] . The tool is adapted for operation with a monocable wireline and through-wellhead pressure fittings. This allows for operations in producing wells with surface pressure. As with any system, a range of seismic information may be obtained in vertical or deviated wells, from check shots to walkaway VSP images.

For example, an offest VSP survey was acquired through tubing and through casing in an abandoned wwell in an inland shallow water field in south Lousiana, USA, using a marine vibroseis unit as a source to acquire high-resolution data. The offset VSP survey was designed to confirm the location of a low-angle fault-indicated by logs-which could not be seen on the surface seismic images. The fault's orientation was needed to reduce the risk of an infill development well and was easily spotted using the offset VSP image.

Using Borehole Geophysics to Integrate Data

A the heart of developments to improve data integration is the recognition of the complementary nature of some measurements. Perhaps the best example of this is the relationship between sonic logs and seismic data. In these two measurements, the physical interaction with the reservoir is the same, but at a different scale of resolution. The sonic tool measures formation compressional slowness, which is dependent on many factors, including the formation porosity and lithology. 

Compressional slowness combined with density provides the one-dimensional acoustic impedance of the formation, the same property that underlies seismic reflections. 

But seismic waves are sensitive only to relative changes in acoustic impedance, unlike sonic slowness measurements, which sample absolute values. Therefore, acoustic impedances from logs provide sufficient information to model most, but not all features of the seismic response. The total travel time measured by sonic logs is a required contribution to the bulk response of the low-frequency surface seismic surveys. Then, synthetic seismograms may be constructed and the response of the formation simulated by altering parameters such as porosity, fluid type and lithology. The synthetics can be used to interpret real data.

Although the scope of VSPs is expanding, the wealth of information relating to lithology, fluid contacts and the seismic responses that they produce is not always used to its fullest extent. This is particularly true when it comes to evaluating and improving the information content of surface seismic data. Now, existing technologies are being used in new ways to provide additional direct quantitative mesurements of the seismic response of the reservoir adjacent to wells.

The next two examples clearly indicate how the integration of all available data may improve understanding of the reservoir. The first example looks at how structural and stratigraphic interpretations may be improved. The second shows how reflection amplitude variation with offset (AVO) from VSPs may be used to calibrate surface seismic AVO.

Morgan's Bluff

In the Morgan's Bluff field of Orange County, Texas, USA, the operator IP Petroleum needed to map the shale edge of its Hackberry reservoir to design a secondary reservoir program.

Substantial existing 2D surface seismic data did not adequately image the reservoir. Therefore, vertical incidence and offset VSPs were shot within a production well. These results were combined with logs and geologic information to map the edge of  the shale. Further, the surface seismic lines were reinterpreted, resulting in an extensive remapping of the Hackberry sand.

The aim was to drill a sidetrack from the shut-in producing Well 8 toward the adjacent Well 10, depending on the exact reservoir boundary, to be determined using the VSP - the Hackberry sand was originally mapped on the strike line that runs through both of these wells.

First , the feasibility of this plan was tested and detailed survey models were constructed using structure maps, log data from the two wells and velocity data from a third well. Borehole seismic data shot in 1986 in the central part of the field were used to construct the general velocity model. In Well 8, sonic logs were available to about 8000 ft , and only nuclear and resistivity logs from there to total depth. A pseudosonic log was constructed from these logs and compared to the velocities from the VSP survey. A synthetic offset VSP was then generated using the same wavefield separation, deconvolution and migration processing to be used with the real data. 

Two scenarios were forward modeled: a gradual shaling out and an abrupt, or faulted, sand termination. From this it was agreed that in either case the shale boundary should be interpretable to within 100 ft using the offset VSP sections, and the go-ahead for the survey was given. Additionally, a second offset VSP to the west of well 8 was designed to confirm the interpretation. A VSP was also to be carried out in Well 8 to build an updated velocity model for migration.





The three downhole surveys were acquired with sources located 4000 ft [1212 m] to the west-southwest, 4300 ft [1300 m] to the southwest and 400 ft [121 m] to the east-southeast. An eight level downhole receiver system was deployed to record 110 levels at 50 ft [15 m] spacing from 8500 to 3000 ft [2575 m to 909 m]. Across each interval, the top and bottom shuttles were overlapped to check for any source amplitude, signature or phase changes during the survey.

Following a standard processing sequence using a flat-layer velocity model and some small velocity changes to match the model to the observed transit times, each of the offset VSPs was migrated. Logs from Well 8 were correlated with the offset VSPs.